In the first stage of hydrocarbon recovery, the sources of energy present in the reservoir are allowed to move the oil, gas, condensate etc. to the producing wells(s) where they can flow or be pumped to the surface handling facility. A relatively small proportion of the hydrocarbon in place can usually be recovered by this means. The most widely used solution to the problem of maintaining the energy in the reservoir and ensuring that hydrocarbon is driven to the producing well(s) is to inject fluids down adjacent wells. This is commonly known as secondary recovery. The fluids normally used are water (such as aquifer water, river water, sea water, or produced water), or gas (such as produced gas, carbon dioxide, flue gas, and various others). If the fluid encourages movement of normally immobile residual oil or other hydrocarbon, the process is commonly termed tertiary recovery.
A prevalent problem with secondary and tertiary recovery projects relates to the heterogeneity of the reservoir rock strata. The mobility of the injected fluid is commonly different from the hydrocarbon and when it is more mobile various mobility control processes have been used to make the sweep of the reservoir more uniform and the consequent hydrocarbon recovery more efficient. Such processes have limited value when high permeability zones (commonly called thief zones or streaks) exist within the reservoir rock. The injected fluid has a low resistance route from the injection to the production well. In such cases, the injected fluid does not effectively sweep the hydrocarbon from adjacent lower permeability zones. When the produced fluid is reused, this can lead to fluid cycling through the thief zone to little benefit and at great cost in terms of fuel and maintenance of the pumping system. As a result, numerous physical and chemical methods have been used to divert injected fluids out of thief zones in or near production and injection wells. When the treatment is applied to a producing well it is usually termed a water (or gas etc.) shutoff treatment. When it is applied to an injection well it is termed a profile control or conformance control treatment.
In cases where the thief zone(s) are isolated from the lower permeability adjacent zones and when the completion in the well forms a good seal with the barrier (such as a shale layer or “stringer”) causing the isolation, mechanical seals or “plugs” can be set in the well to block the entrance of the injected fluid. If the fluid enters or leaves the formation from the bottom of the well, cement can also be used to fill up the well bore to above the zone of ingress. When the completion of the well allows the injected fluid to enter both the thief and the adjacent zones, such as when a casing is cemented against the producing zone and the cementing is poorly accomplished, a cement squeeze is often a suitable means of isolating the watered out zone.
Certain cases are not amenable to such methods by virtue of the fact that communication exists between layers of the reservoir rock outside the reach of cement. Typical examples of this issue include fractures or rubble zones or washed out caverns existing behind the casing. In such instances, chemical gels, capable of moving through pores in reservoir rock have been applied to seal off the swept out zones. When such methods fail, the remaining alternatives are to produce the well with poor recovery rate, sidetrack the well away from the prematurely swept zone, or abandon the well. Occasionally, the producing well is converted to a fluid injector to increase the field injection rate above the net hydrocarbon extraction rate and increase the pressure in the reservoir. This can lead to improved overall recovery but note is that the injected fluid will mostly enter the thief zone at the new injector and is likely to cause similar problems in nearby wells. All of the above are costly options.
Near wellbore conformance control methods generally fail when the thief zone is in widespread contact with adjacent hydrocarbon-containing lower permeability zones. The reason for this failure is that the injected fluids can bypass the treatment and reenter the thief zone having only contacted a very small proportion, or even none of the remaining hydrocarbon. It is commonly known in the art, that such near wellbore treatments are unsuccessful in significantly improving recovery in reservoirs having crossflow of the injected fluids between zones.
A few processes have been developed with the aim of reducing the permeability in a substantial portion of the thief zone or at a significant distance from the injection and production wells. One example of this is the deep diverting gel process is disclosed by Morgan et al. (UK Patent Application No. GB 2255360A). This technology has been used in the field and suffers from sensitivity to unavoidable variations in quality of the reagents which results in poor propagation. The gelant mixture is a two component formulation and it is believed that this characteristic contributed to poor propagation of the treatment into the formation.
The use of swellable cross-linked superabsorbent polymer microparticles for modifying the permeability of subterranean formations is disclosed in U.S. Pat. Nos. 5,465,792 and 5,735,349. However, swelling of the superabsorbent microparticles described therein is induced by changes of the carrier fluid from hydrocarbon to aqueous or from water of high salinity to water of low salinity. There thus exists an ongoing industrial need for novel methods to allow efficient propagation through the pore structure of hydrocarbon reservoir matrix rock with a particular need to modify the permeability of subterranean formations at low pH.